Energy and Climate Change CommitteeWritten evidence submitted by Shell (ISG 23)

Executive Summary

(i)Subject to market price, technological advances and the degree of appraisal of individual resources there will always be some uncertainty over the estimate of global tight/shale gas reserves. However, it is clear that the global potential for tight/shale gas is significant and tight/shale gas will have a significant impact on world energy markets, though this may vary by region.

(ii)Shell believes that tight/shale gas operations can and must be carried out safely, and we appreciate that communities and stakeholders have legitimate questions and concerns including on the environmental impacts of tight/shale gas operations. The regulator is often looked to for answers, and we believe the UK Government is taking the correct approach by reviewing potential impacts and seeking expert advice on the options available to mitigate them.

(iii)Based on the successful development of tight/shale gas in North America in recent years Shell also recognises the potential opportunity that the exploration and development of such resources could provide for the UK. Though exploration in the UK is at a very early stage and the extent of the resource is still uncertain, it could potentially provide many social, economic, trade and energy security benefits, if developed in a socially and environmentally responsible manner. Government, industry and communities need to work together to this end.

(iv)There are many benefits to the UK of maintaining a large role for natural gas in the energy mix, and in the electricity sector in particular. Natural gas can help with all three of the UK’s energy objectives. Gas has the potential to contribute significantly, and in a cost effective manner, to helping the UK meet its CO₂ targets by displacing coal-fired generation. Gas fired power stations are, on a per MWh basis, one of the cheapest electricity generation technologies to build,1 keeping costs down for consumers, whilst also being flexible and quick to build, which can help to ensure security of supply. Longer term, Shell believes that electricity generated from gas will be an essential part of the energy mix as one of the only realistic means of supporting the increased volume of electricity from intermittent renewables. We also believe that gas with carbon capture and storage (CCS) will be a competitive low-carbon technology, that can help achieve even greater cuts in carbon dioxide emissions. To achieve this we need to demonstrate gas CCS as quickly as possible, so that it is ready to deploy on a large scale in the late 2020s.

Q1. What are the estimates for the amount of shale gas in place in the UK, Europe, and the rest of the world, and what proportion is recoverable?

1. There are three basic forms of so-called “unconventional gas (UCG)”: coal bed methane (CBM), basin centered gas and shale gas. In addition, there is a related form of liquids rich shales (more correctly termed light tight oil). These forms of natural gas (or oil) are referred to as “unconventional” because the natural gas (or oil) is not trapped in the same way as it is in the natural gas fields we are familiar with across the Southern North Sea which have formed the backbone of UK natural gas supply in recent decades. The methane produced from unconventional sources is no different than that produced from conventional sources. In general unconventional hydrocarbons are trapped regionally or sub-regionally in low permeability (ie fluids do not flow through them easily) and porosity rocks, whereas the so-called “conventional” hydrocarbons are typically trapped in structures of much smaller areal extent and in rocks with higher porosity and permeability.

Volumes and their significance

2. Masters (1979) was the first person to suggest that the distribution of hydrocarbons was log-normally distributed which implied that the conventional oil and natural gas reserves were the tip of a hydrocarbon iceberg that expanded in volume terms as the more difficult hydrocarbons were examined. This view has manifested itself as the so called resource triangle or tetrahedron (Fig. 1).

Figure 1

RESOURCE TETRAHEDRA

3. Rogner (1997) made the first attempt to assess the volumes of unconventional gas and the results were startling, indicating a huge volume potential. Since then there have been many studies that have either reworked these results or produced new ones, key amongst these additional studies are Kawata et al., 2001, Holditch (2006), NPC Global Oil and Gas Study (2007), Holditch and Mandani (2010), IEA (2009), and EIA (2011). All of these studies have concluded that there are indeed vast volumes of natural gas trapped in the subsurface.

4. The Shell view of global UCG resources is similar with that put forward by the International Energy Agency (IEA) in its extensive look at natural gas markets in 2009 (see figure 2). The IEA estimate recoverable resources of tight gas, shale gas and coalbed methane globally to be more than 380 trillion cubic metres (tcm) (13,700 trillion cubic feet (tcf)), out of a total estimate resource base of 920 tcm (33,100 tcf). This is equivalent to 123 years of current global production, which when added to recoverable conventional gas resources, is estimated to be equivalent to over 250 years of current global production. UCG resources are more widely dispersed compared with conventional. The regions with the largest share of these UCG resources are North America, Asia-Pacific and the Former Soviet Union (FSU).

Figure 2

INTERNATIONAL ENERGY AGENCY ESTIMATES OF UNCONVENTIONAL GAS RESERVES2

5. As well as the success seen in tight/shale gas production in North America, Shell also sees potential for tight/shale gas development across the globe, although it is not expected that the growth will be uniform. This growth will heavily depend on domestic natural gas price developments in different countries and regions, local natural gas infrastructure, government and community support, fiscal regimes and the extent to which environmental issues can be effectively addressed. If sufficient amounts of natural gas are found, Shell’s view is that it is possible to extract tight/shale gas in an economically, environmentally and socially responsible way.

Unconventional Gas in Europe

6. We are not aware of any commercial tight/shale gas production currently in Europe. European geological history is complex, and unlike North America, suffers from a paucity of critical data to assess accurately whether tight/shale gas can ultimately be developed commercially. Given the early stage of exploration there is still great uncertainty over the volumes of economically recoverable natural gas in Europe, illustrated by the variable estimates in the literature.

7. The key geological components appear to be present in many sedimentary basins, but simple extrapolation from North American analogues is difficult. At this time, it is not evident which areas of Europe will ultimately host commercial UCG production. Better assessment of UCG potential will first require early (one–four years) investment in seismic operations, exploration drilling and geological studies across many potential areas, followed by significant investment in appraisal drilling and production testing (two–five years). It is estimated that 20–40 wells (exploration, appraisal and pilot) will be required to prove commerciality in many basins. Exploration and production companies with diversified portfolios and stronger revenues are better able to absorb this exposure, but to succeed they will also need government support to enable the right fiscal framework and appropriate permitting and other regulatory conditions.

8. The volumes of natural gas in place need to be turned into economically accessible volumes. To do this requires some additional assumptions:

(1)Recovery factor and drainage area values need to enable the volume of technically recoverable natural gas to be estimated.

(2)The total surface area of the accumulation needs to be discounted for the area that is not developable due to terrain, population, infrastructure (eg roads), regulations (ie distance from buildings), areas where drilling is not allowed (eg typically national parks), or critical water resources.

(3)Evaluation of the fraction of the technically recoverable and accessible volumes that is economically accessible.

(4)Other constraints such as the availability of infrastructure, equipment, knowledge etc need to be taken into consideration.

9. An inverted pyramid (Fig. 3 below) best describes the volumes that are economically recoverable.

Figure 3

MOVING FROM NATURAL GAS IN PLACE TO ECONOMICALLY RECOVERABLE VOLUMES

10. Estimating the proportion of the technically recoverable and accessible volumes that are also economic is no easy matter. There is no single answer because a large number of other variables may come into play, many of which vary significantly with time. The economics of tight/shale gas depend largely on five factors:

The total recoverable natural gas per well—typically the total recoverable natural gas per well from developed tight/shale gas fields is in the range one to 10 bcf/well, but the recovery rate varies significantly with geology and can therefore vary within any given resource.

Average long term natural gas price—the typically low ultimate recoveries achieved per well mean that a continual focus is required on unit cost reduction and technology deployment to increase ultimate recovery. In this environment fluctuations in gas price can therefore have a large impact on project economics, requiring investment decisions in these resources to take a long term view of natural gas prices.

The well costs—well and completion costs typically make up 70–90% of the total project costs and so have a huge impact on the economic viability of a project. The principle variable controlling well costs is the total depth of the well and the length of any horizontal section.

Infrastructure costs—successful North American developments to date have typically benefited from a local abundance of natural gas distribution networks and of mid-stream companies willing to develop infrastructure. Elsewhere in the world such infrastructure may not exist at the outset putting a heavy financial burden on any tight/shale gas project.

Terms and conditions—the fiscal regimes for natural gas development vary greatly around the world and this will impact whether or not some of the tight/shale gas volumes present will ever be developed.

11. As well and completion costs dominate the average project’s economics, their reduction over time can be extremely important in improving the profitability of a project. So-called learning curves need to be built into forward looking economic assessments of opportunities. These take into account a risk assessment that with time, in any given project, it will be possible to build up experience and drill wells faster and cheaper, streamlining and optimizing designs without compromising safety or productivity. Our experience has taught us that it is not only possible to learn within a given project but to cross-learn between projects to accelerate learning considerably as shown in Figure 4, which illustrates how drill time (normalized to 100 days) can reduce over the development of an asset and across assets. Another benefit of learning curves is that areas of the resource that were once thought to be uneconomic, may become economic later in the development program as operational efficiency and engineering effectiveness increases.

Figure 4

WELL DELIVERY TIME LEARNING CURVES IN NORTH AMERICAN UNCONVENTIONAL GAS PLAYS

12. Advances in technology which increase the recovery factor per well or decrease costs will increase the volumes of economically recoverable natural gas. For instance, in the Barnett shale the average productivity per well has steadily increased as a result of increasing the length of the horizontal sections of the wells and the number of hydraulic fracture stages used.

Liquid Rich Shales otherwise known as (Light) Tight Oil

13. In recent years there has been a growth in the production of oil from tight rocks. These rocks can be tight sandstone reservoirs, shale analogous to shale gas, tight carbonates such as the Eagle Ford, or silicilite such as the Monteray in California. Shell terms all these types Liquid Rich Shales, while industry in general uses the term tight oil. With the exception of coalbed methane, there are oil equivalents to all the forms of UCG we have already discussed. We now know a lot about how to estimate the volumes of natural gas trapped and how to produce it as there are now many active fields in North America. The same technology, ie long horizontal wells and hydraulic fracturing, has also been used to produce oil from tight rocks in North America sparking the reversal in the decline of North American onshore oil production.

14. Some publications have suggested that there are significant amounts of light tight oil yet to be found. Although it is certain that oil can be produced there are fundamental reservoir engineering reasons why it is unlikely to be as prolific as tight/shale gas. The industry is at an early stage of development in North America and time will be needed to determine how this oil resource might be developed. Potential does also exist globally, but it is also too early to determine what the true potential might be.

Q2. Why are the estimates for shale gas so changeable?

15. It should be noted that, outside of North America and with the exception of Australia where CBM developments are moving apace, elsewhere in the world there is no large scale tight/shale gas production. There are many tests going on around the world currently eg in Poland and China, but it remains to be seen how these speculative volumes quoted in the global studies translate to delivered volumes. To understand the speculative character of these numbers it is important to appreciate how these numbers are estimated. There are a number of ways that have been employed to estimate the volumes of gas in place, and in approximate order of increasing reliability these are:

(a)Simple scaling between what is known of North American basins and those outside North America.

(b)Geological analogue approach—finding a North American analogue for a given basin and scaling the result.

(c)Comparison of a given formation within a basin against a set of conditions necessary for the presence of UCG eg of the volume of natural gas generated from the source rock, and then extrapolation of the volumes present from an estimation of the porosity, natural gas saturation, thickness and extent.

(d)Data from well logs on the presence of natural gas, its saturation and the porosity that can then be extrapolated over the likely extent of the accumulation.

(e)As per (d) but with the addition of production data most notably the estimated ultimate recovery per well for the formation in question.

(f)Estimates based purely on the distribution of estimated ultimate recoveries for a given formation based on production data for that formation extrapolated over the resource area.

16. The data requirements grow significantly from method (a) to (f), such that methods based on (e) or (f) are only possible in established North American resources.

17. So the range of values quoted by different sources reflect a number of different factors:

(1)The method of analysis chosen, noting that only methods (a) to (c) (maybe in some areas (d)) are possible outside of North America.

(2)The level of detail versus extrapolation ie how many basins were actually looked at in detail versus how many used extrapolation to estimate their potential.

(3)Cut-off values eg thickness of the shale concerned could vary between studies.

(4)What volume is being discussed, in place volumes, recoverable volumes, or economic volumes (if so, at what commodity price and other cost assumptions of drilling).

(5)Is only shale gas being included or all forms of unconventional gas?

18. Given the lack of data to accurately assess reserves outside of North America, it will take some time before more accurate estimates become available and the estimates start converging. Nevertheless the consensus is that the potential resource is large.

Q3. What are the prospects for offshore shale gas in the UK and the Continental Shelf?

19. In Europe, the exploration of tight/shale gas is still in its early stage and no commercial production is taking place at present and a significant period will be required for development. Over the period 2005 to 2011 there were of the order of 25 shale gas wells drilled in Europe, all of them exploratory, while in the same period in North America, in the major shale gas resources alone, some 40,000 wells were drilled.

20. So far all tight/shale gas developments that we are aware of are onshore. This does not mean that tight/shale gas does not exist offshore, it almost certainly does. The development of tight/shale gas resources requires a relatively high well density with multi-well pads being positioned every few kms. This far exceeds the well density that is currently economically feasible on an offshore platform and of course the costs rise dramatically with the number of platforms needed. As a result in the medium to long term, without any significant technological breakthroughs, it is unlikely that large UCG accumulations will be economically viable offshore.

Q4. Should the UK consider setting up a wealth fund with the tax revenue from shale gas?

21. We consider that how the tax revenues are used, is a matter for government to determine.

Q5. What have been the effects of shale gas on the LNG industry?

22. As mentioned previously, the tight/shale gas revolution means the world now has an estimated 250 years of worldwide recoverable natural gas resources at current production rates.3 The biggest impact has been in the US, where many now believe that 100+ years of reserves can be economically produced. The growth in the production of shale gas in the US has increased the disparity between North American natural gas prices and European natural gas or Asian Liquified Natural Gas (LNG) prices. In addition, the increase in North American natural gas supplies has boosted confidence in natural gas and is paving the way to demand growth in North America. For example, it increased attractiveness for: natural gas to power, natural gas moving into the transport sector, the potential for natural gas to liquids and natural gas to chemicals.

23. The impact on the global LNG market will depend on the success of current efforts to export LNG from North America. These exports will be produced by greenfield projects as for example the Shell-led LNG Canada project, as well as conversion of existing LNG import terminals in the United States. New liquefaction export capacity in the United States may begin to operate as early as 2015. A wide range of US LNG export projects have been announced totalling 16.83 billion cubic feet per day4 (bcfd). Currently only one, the Sabina Pass project, has received a 9 million tonnes per annum (mtpa) export license for LNG exports to countries not governed by a free trade agreement with the United States.

24. Through eventual North American LNG export capacity, the North American tight/shale gas resources help to create the opportunity for global LNG buyers to further diversify supply sources. Already today we see LNG volumes, destined for the United States, being diverted to meet the growing LNG import requirements of other markets, such as Europe and Asia.

25. In addition, LNG exports from Australia will increase significantly after 2014,5 partly fuelled by the production of CBM. Australia also has other forms of tight/shale gas potential but the development of the CBM resources there is more advanced.

26. In terms of price impacts on markets it is too early to know exactly what the impact of tight/shale gas will be. It is likely that development of these resources will encounter different challenges in different parts of the world, almost all being more complex than in the United States (technical, community, regulatory). Hence the speed and cost of developing tight/shale gas will vary around the world.

Q6. Could shale gas lead to the emergence of a single, global gas market?

27. The recent growth in the LNG market has increased the diversity of supply sources and allowed more flexibility in the natural gas supply chain, enabling more interconnection between regional markets. The emergence of tight/shale gas in the United States has increased the availability of divertible LNG cargoes that were previously destined to supply the United States. The availability of divertible LNG cargoes helps the global LNG market to balance more effectively. For example, diversions of LNG cargoes helped Japan to satisfy additional natural gas demand following last year’s earthquake.

28. The regional price disparities we see today are based on supply and demand in the various regional markets, and due to regulatory differences between different markets. The complexity and costs associated with moving natural gas long distances (primarily via LNG) and the relatively small percentage of natural gas moved as LNG (<10% of total natural gas production6), the impact LNG can have in smoothing out these regional differences is limited. As the proportion of the natural gas market that is traded through LNG increases in future (estimated to grow to ~16% of total natural gas production by 20257), further connectivity will also develop.

29. The key question, however, is whether the UK (and North West Europe) can connect into a wider global natural gas/LNG market. This is possible already today given the abundance of regasification terminals in the region and the increase of shorter term trades in the LNG market. As published by GIIGNL,8 the spot market for LNG increased to 25% of global LNG trade in 2011. In addition, in 2011 the UK received LNG from Algeria, Egypt, Nigeria, Norway, Trinidad & Tobago, Qatar, Yemen and US, which demonstrates the global diversity of supplies available to the UK.

30. What is clear is that the recent additions to global natural gas reserves due to sUCG and the increased diversity of new upstream supply areas will likely increase the importance of natural gas in the global energy mix.

Q7. What are the effects on investment in lower-carbon energy technologies?

31. We believe that there is a vital long term role for natural gas in a low-carbon economy, particularly in the power sector as the natural complement to intermittent renewables which need back-up power. Natural gas can help maintain the stability of the electricity system as it is flexible and reliable and can therefore respond during the extended periods when the electricity output from wind decreases, a service that will be required more frequently in the future as the share of renewables in the electricity mix increases. Natural gas is viewed as one of the least carbon intensive technologies to use for helping balance the electricity grid, and if this role is not appropriately recognized in policy it may lead to more carbon intensive forms of load balancing, such as coal.

32. So natural gas and renewables generation technologies should not be seen as being in competition, as they are both required to meet the UK’s energy goals of affordable, secure and low-carbon energy. In addition, the major energy transformations that are required both in the UK and the rest of the Europe to meet both climate and energy security goals carry significant risks and uncertainties. A key way to mitigate these is to incorporate into the transition process the knowledge gained as sector learning curves for new technologies develop and supply chains evolve. Growth in natural gas-fired power in the short to medium term enables a more measured transition to renewables and nuclear, allowing the optimization of technology and driving down of cost.

Q8. What is the potential impact on climate change objectives of greater use of shale gas?

33. According to the IEA, natural gas currently provides about 20% of the global primary energy demand9 and accounts for 20% of total global Greenhouse Gas (GHG) emissions from the energy sector. Tight/shale gas accounts for less than 5% of total GHG emissions from the energy sector. In contrast, coal accounts for 27% of the energy demand but 43% of GHG emissions.10

34. There are many benefits to the UK energy sector and wider economy in maintaining an important role for natural gas in the UK electricity mix. The benefits that the use of natural gas can bring from a macro-economic perspective are often underestimated. With deficits and government debt at historically high levels, there is an acute need for strict budget discipline. Maintaining the affordability of electricity prices is also important from a competitive perspective. Any increases in UK electricity prices that are not mirrored in other countries could impact industry’s competitiveness and have a negative impact on jobs. Most countries will find that natural gas is far more affordable than any other source of electricity, especially in front-end (capital cost) investment terms. There are also significant benefits of developing domestic tight/shale gas resources, as highlighted by a recent report from the Institute of Directors that indicated UK tight/shale gas reserves could create up to 35,000 jobs.11

35. The security of supply benefits of natural gas have been outlined in our response to the previous question. In terms of its contribution to the reduction in emissions, replacing coal-fired generation with natural gas is the fastest and cheapest way of achieving immediate reductions, given that, on average, gas emits 50% less CO₂ than coal when used to produce the same amount of electricity.12

36. Longer-term, natural gas fired power plants may be retrofitted with CCS which has potential to reduce emissions by up to 90%. CCS is technically established (all elements are well proven) but the market still has to see scaled-up demonstrations and then widespread application. This may be achievable in the 2020s and, provided the appropriate regulatory framework and government support is established, we may see large scale CCS take off by 2030. In the longer term, as these technologies move to “nth of a kind status” (or mature status), the levelised costs of CCS equipped plant should make them very cost competitive with other technologies such as offshore wind and solar PV.13

37. So in the period to 2030 there are several arguments for unabated natural gas generation. This is consistent with meeting the UK’s 2050 targets, since CCS may be retrofitted to natural gas plants after 2030 and reduce their carbon footprint. Shell analysis has shown that the UK 2050 target would need CCS build-out rates of one to two GW per year from 2030 to 2050 which is equivalent to 1.5% to 3% of current UK fossil fuel generation capacity. This needed CCS build rate is realistic when compared to the UK’s natural gas fired power build activity from 1991–2002 which was between 0.5 and 3.5 GW a year.

38. These benefits can be provided by tight/shale gas as well. According to the IEA, the emissions incurred from producing tight/shale gas are not significantly different from conventional natural gas. The IEA has estimated that well-to-burner emissions from tight/shale gas exceed those from conventional natural gas by as little as 3.5% in best case scenario and by 12% in worst.14 At Shell we endeavour to manage our operations to reduce emissions and we measure, catalogue and report emissions to the relevant authorities. GHG emissions from shale gas-fired power are still only around half of those from coal, across the lifecycle from production to use.15 Shifting to natural gas can have a significant impact on emissions. For example, according to the IEA, US emissions have now fallen by 430 Mt (7.7%) since 2006, the largest reduction of all countries or regions. This development has arisen from lower oil use in the transport sector (linked to efficiency improvements) and a substantial shift from coal to natural gas in the power sector.

39. Shell published in mid-2011, its Onshore Tight Sand/Shale Oil and Gas Operating Principles.16 We believe that a similar approach taken across the industry would help improve standards, reduce the environmental risks and promote public confidence in this sector.

October 2012